SPE Production & Operations
Volume 23, Number 4, November 2008, pp. 498-511

Summary

Non-Darcy and multiphase flow effects in hydraulic fractures have been well documented in the last several years. The pressure losses caused by these phenomena are accepted widely to be of great significance in most gas-well completions in the United States and elsewhere (Palisch et al. 2007; Forchheimer 1901; Milton-Tayler 1993a; Penny and Jin 1995; Flowers et al. 2003; Miskimins et al. 2005; Handren et al. 2001; Lolon et al. 2004; Vincent 2004; Olson et al. 2004). Although the importance in gas wells is evident, the authors pose the question of whether non-Darcy and multiphase flow effects are of concern in typical oil wells in Russia.

For the analysis, the authors evaluate three primary categories of Russian production wells: gas wells, oil wells producing above the bubblepoint, and oil wells producing below the bubblepoint. For each category, the authors describe the significance of non-Darcy and multiphase flow effects by use of the fracture-flow theory and state-of-the-art fracture-production models. This paper will illustrate that non-Darcy and multiphase flow effects can substantially decrease the production potential of gas wells and the many oil wells found in Russia that are producing below the bubblepoint.

Historically, Russian oil wells have been operated intentionally above the bubblepoint. However, more-aggressive well designs have recently been shown to increase production more than threefold. The authors explore the economics of producing these wells below the bubblepoint and show that for these more aggressive strategies, the effects of non-Darcy and multiphase flow can be significant and should be accommodated during fracture design.

The authors propose solutions for mitigating these effects with various modifications to the fracture design, including the impact of proppant selection on performance. Several operators within Russia have already successfully accounted for these phenomena in their fracture designs, and new field examples are explored, analyzed, and presented in the paper. Recent field results are presented for Gazpromneft’s Achimovskoya formation BV8 in the Tomsk region (western Siberia) and BP-TNK’s field near Buzuluk in the Orenburg region (Volga-Urals). The results found here are compared to published results from the Achimovskoya sandstone in the Kalchinskoye oil field, the BP12 formation of the Vyngayakhinskoe oil field, the Priobskoye and Sugmutskoe oil fields, and Gazprom’s Yamburgskoe gas-condensate development.

Introduction

In the last decade, emphasis has been placed increasingly on the conductivity of the proppants used in fracture stimulations, especially for medium-to-high-permeability formations. The conductivity of the fracture can be calculated by finding the product of the permeability of the fracture and the fracture width. It can be represented by the following equation:

• [Eqn 1]

Typically, analysis of the flow potential of a well has involved the determination of the dimensionless fracture conductivity (F_cd ) relating the flow potential of the fracture to that of the reservoir. F_cd is calculated by use of the following equation:

• [Eqn 2]

For steady- or pseudosteady-state flow in oil wells, several authors, including Prats (1961) and McGuire and Sikora (1960), have developed correlations that enable the engineer to use F_cd to predict the benefits of the fracture stimulation, yielding a method that balances fracture half-length with fracture conductivity for stimulation design. Fig. 1 illustrates Prats' correlation (where k_p is the permeability of the fracture, k_frac, and k_f is the permeability of the formation, k_form). Increasing the F_cd of the fracture leads to an enlargement of the effective wellbore radius (r_w ’/X_f ). However, after an F_cd of ≈10, the incremental effective radius slows for a given increase in F_cd .

Although these correlations continue to serve the industry well, it is critical that a realistic conductivity be used when calculating F_cd (Pearson 2001). Fig. 2 shows the "reference" or "laminar" conductivity for several different intermediate-density ceramic proppants commonly used in Russia. In this figure, the proppant has been subjected to 4,000-psi stress (272 atm). However, it is critical to note that these reference values have not been corrected for non-Darcy or multiphase flow, gel damage, filter cake, fines plugging, cyclic stress-loading, long-term proppant degradation, and many other phenomena that will increase the pressure losses within the fracture.

Vincent et al. (1999) have pointed out that the American Petroleum Institute (API) conductivity test used in many fracture-production models significantly overpredicts the conductivity of proppant. This can lead to selection of a proppant that appears adequate when evaluated at reference conditions but is actually severely inadequate at realistic producing conditions. Many papers have documented the benefits of increasing the conductivity of hydraulic fractures, in both gas and oil wells, at a variety of production rates and flowing conditions (Vincent 2002; Carbo Ceramics 2007).

© 2008. Society of Petroleum Engineers

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History

• Original manuscript received: 16 September 2006
• Meeting paper published: 3 October 2006
• Revised manuscript received: 19 February 2008
• Manuscript approved: 13 March 2008
• Version of record: 15 November 2008